PSD Greenhouse Gas Draft Permit for Enterprise Products ... · PDF file6.2 Regeneration Air Heater ..... 6-9 6.2.1 Step 1 – Identification of Potential Control Technologies ... fired

Application for Prevention of Significant Deterioration

Air Permit Greenhouse Gas Emissions

Enterprise Mont Belvieu Complex Propane Dehydrogenation Unit

Submitted by

Enterprise Products Operating LLC P.O. Box 4324

Houston, Texas 77210-4324

December 2012

I:\Projects\Enterprise\Texas\Mt Belvieu\PDH\GHG Permit\GHG Application.doc i

Table of Contents List of Sections

Section 1 Introduction ............................................................................................................ 1-1

Section 2 Administrative Information and PSD Applicability Forms ...................................... 2-1

Section 3 Area Map and Plot Plan ........................................................................................ 3-1

Section 4 Process Description .............................................................................................. 4-1

Section 5 Emission Rate Basis ............................................................................................. 5-1 5.1 Combustion Units ................................................................................................. 5-1

5.1.1 Reactor Charge Heater ............................................................................ 5-1 5.1.2 Waste Heat Boiler (WHB) ........................................................................ 5-2 5.1.2.1 Combustion Turbines ............................................................................... 5-2 5.1.2.2 Regeneration Air Heater .......................................................................... 5-2 5.1.2.3 WHB Duct Burner ..................................................................................... 5-3 5.1.2.4 Reactor Air Effluent and Ejector ............................................................... 5-3 5.1.2.5 Decoke ..................................................................................................... 5-3 5.1.3 Auxiliary Boilers ........................................................................................ 5-4 5.1.4 Combustion Unit Emissions Caps ............................................................ 5-4

5.2 Flare Emissions ..................................................................................................... 5-4 5.3 Process Fugitive Emissions .................................................................................. 5-5 5.4 Diesel Engines ...................................................................................................... 5-5

Section 6 Best Available Control Technology ....................................................................... 6-1 6.1 Reactor Charge Heater ......................................................................................... 6-2

6.1.1 Step 1 – Identification of Potential Control Technologies ......................... 6-2 6.1.2 Step 2 – Elimination of Technically Infeasible Alternatives ...................... 6-3 6.1.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness .. 6-3 6.1.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to

Least Effective .......................................................................................... 6-4 6.1.5 Step 5 – Selection of BACT ..................................................................... 6-8

6.2 Regeneration Air Heater ........................................................................................ 6-9 6.2.1 Step 1 – Identification of Potential Control Technologies ......................... 6-9 6.2.2 Step 2 – Elimination of Technically Infeasible Alternatives ...................... 6-9 6.2.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-10 6.2.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to

Least Effective ........................................................................................ 6-10 6.2.5 Step 5 – Selection of BACT ................................................................... 6-11

6.3 Waste Heat Boiler .............................................................................................. 6-11 6.3.1 Step 1 – Identification of Potential Control Technologies ....................... 6-11 6.3.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-12 6.3.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-12 6.3.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to


6.4 Auxiliary Boilers .................................................................................................. 6-14 6.4.1 Step 1 – Identification of Potential Control Technologies ....................... 6-14 6.4.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-15 6.4.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-15 6.4.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to

Least Effective ........................................................................................ 6-16

I:\Projects\Enterprise\Texas\Mt Belvieu\PDH\GHG Permit\GHG Application.doc ii

6.4.5 Step 5 – Selection of BACT ................................................................... 6-17 6.5 Combustion Turbines ......................................................................................... 6-17

6.5.1 Step 1 – Identification of Potential Control Technologies ....................... 6-17 6.5.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-18 6.5.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-18 6.5.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to


6.6 Flare .................................................................................................................... 6-20 6.6.1 Step 1 – Identification of Potential Control Technologies ....................... 6-20 6.6.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-21 6.6.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-21 6.6.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to


6.7 Fugitives (EPNs FUG-PDH & FUG-NGAS) ......................................................... 6-22 6.7.1 Step 1 – Identification of Potential Control Technologies ....................... 6-22 6.7.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-22 6.7.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-22 6.7.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to


6.8 Diesel Engines .................................................................................................... 6-23 6.8.1 Step 1 – Identification of Potential Control Technologies ....................... 6-23 6.8.2 Step 2 – Elimination of Technically Infeasible Alternatives .................... 6-23 6.8.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness 6-23 6.8.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to


List of Tables Table 1F Air Quality Application Supplement ....................................................................... 2-3 Table 2F Project Emissions Increase ................................................................................... 2-4 Table 3F Project Contemporaneous Changes ..................................................................... 2-5 Table 5-1 Proposed GHG Emission Limits ............................................................................ 5-6 Table 6-1 Approximate Cost for Construction and Operation of a Post-Combustion CCS

System for PDH Plant ......................................................................................... 6-25

List of Figures Figure 3-1 Area Map ............................................................................................................... 3-2 Figure 3-2 PDH Unit Plot Plan ................................................................................................ 3-3 Figure 4-1 Simplified Process Flow Diagram .......................................................................... 4-2

List of Appendices

Appendix A Emissions Calculations Appendix B RBLC Database Search Results

1-1

Section 1 Introduction

Enterprise Products Operating LLC (Enterprise) currently operates the Mont Belvieu Complex,

an oil and gas production facility in Chambers County. Enterprise proposes to construct a

Propane Dehydrogenation (PDH) Unit at the Complex with a design propylene production

capacity of 1.654 billion pound per year. A hydrogen byproduct will also be produced. Both the

propylene and hydrogen products will be sent offsite via pipeline. The new facilities in the PDH

Unit will include:

Ten parallel catalytic reactors that convert propane feed to propylene, One Reactor Charge Heater, One Regeneration Air Heater, One Waste Heat Boiler with duct firing capability, Two Auxiliary Boilers, Two Regeneration Air Compressors, Two Regeneration Air Combustion Turbines, Cooling tower, Hydrogen Recovery (PSA) Unit, Ancillary tanks, Emergency pump engines, Process flare, and Wastewater treatment facilities.

A New Source Review permit amendment application has also been submitted to TCEQ for this

project. The project triggers NNSR for VOC and PSD review for NOx, CO, PM/PM10/PM2.5, SO2,

and H2SO4, for which TCEQ has approved permitting programs and PSD for greenhouse gas

(GHG) emissions, for which TCEQ has not implemented a PSD permitting program. The

purpose of this permit application is to obtain a PSD permit for the GHG emissions associated

with the project.

This document constitutes Enterprise’s GHG PSD permit application for the modifications

described above. Because EPA has not developed application forms for GHG permitting,

TCEQ forms are used where deemed appropriate. The application is organized as follows:

Section 1 identifies the project for which authorization is requested and presents the application

document organization.

1-2

Section 2 contains administrative information and completed TCEQ Federal NSR applicability

Tables 1F, 2F, and 3F.

Section 3 contains an area map showing the facility location and a plot plan showing the

location of each emission points with respect to the plant property.

Section 4 contains more details about the proposed modifications and changes in operation and

a brief process description and simplified process flow diagram.

Section 5 describes the basis of the calculations for the project GHG emissions increases and

includes the proposed GHG emission limits.

Section 6 includes an analysis of best available control technology for the new and modified

sources of GHG emissions.

Appendix A contains GHG emissions calculations for the affected facilities.

Appendix B contains the results of an RBLC database search for GHG controls used on gas

fired heaters and boilers.

2-1

Section 2 Administrative Information and PSD Applicability Forms

This section contains the following forms:

Administrative Information

TCEQ Table 1F

TCEQ Table 2F

TCEQ Table 3F

Tables 1F, 2F and 3F are federal NSR applicability forms. Because this application covers only

GHG emissions, and PSD permitting of other pollutants is being conducted by TCEQ, these

forms only include GHG emissions. As shown in both the Table 1F and 2F, GHG emissions

from the project exceed 75,000 tpy of CO2e; therefore, a Table 3F, which includes the required

netting analysis, is also included. The net increase in GHG emissions exceeds 75,000 tpy of

CO2e; therefore, PSD review is required.

Permit No.: TBD

Project Name: PDH Unit

December A B

FIN EPN Facility Name

1 HR15.101 HR15.101 Combustion Unit Cap TBD - - 1,281,586 - 1,281,586 0 1,281,586

2 HR15.103 Waste Heat Boiler Burner TBD

3 HR15.102 Regeneration Air Heater TBD

4 GT26.101ARegen Air Comp. Gas

Turbine ATBD

5 GT26.101BRegen Air Comp. Gas

Turbine BTBD

6 BO10.103A Auxiliary Boiler A TBD

7 BO10.103B Auxiliary Boiler B TBD

8 SK25.801 SK25.801 Process Flare, Routine TBD - - 2,820.56 2,820.56 0.00 2,820.56

9 SK25.801 SK25.801 Process Flare, MSS TBD - - 4,439.30 4,439.30 0.00 4,439.30

10 FUG-PDH FUG-PDH Process Fugitives TBD - - 5.24 5.24 0.00 5.24

11 FUG-NGAS FUG-NGASNat. Gas Pipeline

FugitivesTBD - - 273.75 273.75 0.00 273.75

12 PM18.803 PM18.803 Fire Water Pump Engine TBD - - 16.14 16.14 0.00 16.14

13 PM18.850C PM18.850C Raw Water Pump Engine TBD - - 8.40 8.40 0.00 8.40

14

15

Page Subtotal9: 1,289,149

Project Total: 1,289,149

Difference

(B-A)6

(tons/yr)

Correction7

(tons/yr)

Project

Increase8

(tons/yr)

Affected or Modified Facilities2Permit

No.

Actual

Emissions3

(tons/yr)

Baseline

Emissions4

(tons/yr)

Proposed

Emissions5

(tons/yr)

Projected Actual Emissions(tons/yr)

DW37.101

Baseline Period: NA

TABLE 2FPROJECT EMISSION INCREASE

Pollutant1: GHG

12/18/2012

Table 3FProject Contemporaneous Changes

Company: Enterprise Products Operating LLCCriteria Pollutant: GHG

Permit Application No. TBDA B C

No. PROJECT DATEEMISSION UNIT AT WHICH

REDUCTION OCCUREDPERMIT

NUMBERPROJECT NAME OR

ACTIVITYPROPOSED EMISSIONS

BASELINE EMISSIONS

DIFFERENCE (A-B)

FIN EPN (tons / year) (tons / year) (tons / year)

1 July 1, 2015 HR15.101 HR15.101 TBD PDH Unit 1,281,586 0 1,281,586 1,281,5862 July 1, 2015 HR15.103 TBD PDH Unit3 July 1, 2015 HR15.102 TBD PDH Unit4 July 1, 2015 GT26.101A TBD PDH Unit5 July 1, 2015 GT26.101B TBD PDH Unit6 July 1, 2015 BO10.103A TBD PDH Unit7 July 1, 2015 BO10.103B TBD PDH Unit8 July 1, 2015 SK25.801 SK25.801 TBD PDH Unit 2,821 0 2,821 2,8219 July 1, 2015 SK25.801 SK25.801 TBD PDH Unit 4,439 0 4,439 4,439

10 July 1, 2015 FUG-PDH FUG-PDH TBD PDH Unit 5 0 5 5

11 July 1, 2015 FUG-NGAS FUG-NGAS TBD PDH Unit 274 0 274 274

12 0 0

13 0 0

14 0 0

15 0 0

16 0 0

17 0 0

18 0 0

19 0 0

20 0 0

PAGE SUBTOTAL: 1,289,125

Summary of Contemporaneous Changes TOTAL : 1,289,125

CREDITABLE DECREASE OR

INCREASE

(tons / year)

DW37.101

3 12/18/2012

3-1

Section 3 Area Map and Plot Plan

An Area Map showing the location of the Mont Belvieu Complex is presented in Figure 3-1. A

plot plan showing the location of the modified facilities is presented in Figure 3-2.

308000 308500 309000 309500 310000 310500 311000 311500 312000 312500 313000 313500 314000 314500 315000 315500 316000 316500 317000 317500 318000

UTM Easting (meters)

3302

000

3302

500

33030

00

33

035

00

33

040

00

330

450

0330

500

03305

500

3306

000

3306

500

33

070

00

33

075

00

33

0800

0330

850

0

UT

M N

ort

hin

g (

mete

rs)

FIGURE 3-1Area Map

411 North Sam Houston ParkwaySuite 400,Houston, Texas , 77060

Enterprise Products Operating LLCMont Belvieu Complex

Source: mytopo.com/Zone: 15Coordinate Datum: NAD 83

North

Property Line

3,000 ft

Scale

(feet)

3-2

Proposed PDH Unit

0 1000 2000 3000 4000 5000

Emission Points are out of Figure boundaries

411 North Sam Houston Parkway Suite 400, Houston, Texas , 77060.

Enterprise Products Operating LLC Mont Belvieu Complex

Figure 3-2 Proposed PDH Unit

4-1

Section 4 Process Description

A brief overview of the process is included below, and a simplified process flow diagram of the

PDH process is shown in Figure 4-1. A block flow diagram of the Waste Heat Boiler is shown in

Figure 4-2.

The proposed PDH Unit will convert propane to propylene over a catalyst. The unconverted

propane is recycled so that propylene is the only net product. A hydrogen byproduct is also

produced.

Operating conditions are selected to optimize the relationships among selectivity, conversion,

and energy consumption. Side reactions occurring simultaneously with the main reaction cause

the formation of some light and heavy hydrocarbons as well as the deposition of coke on the

catalyst.

The process takes place in fixed-bed reactors that operate on cyclic basis. In one complete

cycle, hydrocarbon vapors are dehydrogenated; the reactor is then purged with steam and

blown with air to reheat the catalyst and burn off the small amount of coke that is deposited on

the catalyst during the reaction cycle. These steps are followed by an evacuation and

reduction, and then another cycle is begun.

A key feature of the process is that the heat absorbed during the endothermic dehydrogenation

period is obtained by the adjustment of the air and hydrocarbon inlet temperatures and by the

oxidation of the coke.

The low temperature recovery area, product purification, and refrigeration systems have been

integrated to optimize energy efficiency. The design contains:

Cascade propylene and ethylene refrigeration system.

A high efficiency cold box design that minimizes equipment count and refrigerant compressor power demand.

A low pressure Deethanizer that eliminates the need for feed pumps.

A low pressure Product Splitter integrated with the propylene refrigeration system.

EPNRegen. Gas Return

HR15.101 (Charge Heater) Tail Gas

Cooled Offgas Deethanizer Vent

Propylene

Product

Fuel Gas (used internally)

Hydrogen Byproduct Feed

porization

um Botm

s

D il

Reactor Efluent

Recycle Propane

Reflux

Product Splitter ovhdPROPYLENE

REFRIGERATION SYSTEM

DW 37.101 (Waste Heat Boiler)

Import Fuel Gas

Import Fuel Gas

Reduction Gas

FEEDVAPORIZATION /

PREHEAT REACTORS PRODUCT PURIFICATION

REGENERATIONGAS SYSTEM

PSA UNIT

Fresh PropaneFeed

EPN

EPN

Regen Air

Fuel Gas (used internally)

EPN

GT26.101A/B Gas Turbine Bypass Stacks

Note: Import fuel gas may be either natural gas or ethane.

Propane Dehydrogenation Unit Mont Belvieu , TX

Figure 4‐1 Block Flow Diagram ‐ Overall Process

411 N. Sam Houston Parkway E. Suite 400,

Houston, Texas, 77060

SK25.801

Vap

Dru Deoiler

Overhead

SUPPORT FACILITIES

C4+ Products C4+ RECOVERY

Steam to Process

B010.103BB010.103A

Fuel Gas

Water Makeup/Return

AUXILIARY BOILERS

EPN EPN CT13.801

Water Return

Water to Exchangers

COOLING TOWER

EPN EPN

Misc. Vents from Process

PROCESS FLARE

Natural Gas

4‐2

Bypass Vents

Fuel Gas

Steam

Exhaust

Fuel Gas

Air

Air, VOC, CO

Fuel Gas

Air

GAS TURBINES GT26.101A GT26.101B

REGENERATION AIR HEATER HR15.102

REACTOR EVAC EJECTOR EXHAUST

REACTORS

DW37.101EPN

STEAMHEADER TO PROCESS

BFW TO Users

EPN

WASTE BOILER

Note: Fuel gas may be natural gas, ethane, or process offgas.

Propane Dehydrogenation Unit Mont Belvieu , TX

Figure 4‐2 Waste Heat Boiler Block Flow Diagram

411 N. Sam Houston Parkway E. Suite 400,

Houston, Texas, 77060

Boiler Feed Water(BFW)

Air, VOC

VOC REMOVAL BED No. 1 (Oxidation Catalyst)

Stack

WHB DUCT BURNER BO10.101

VOC REMOVAL BED No.2 (Oxidation Catalyst)

NH3

SCR CATALYST

CONDENSATE

4‐3

5-1

Section 5 Emission Rate Basis This section contains a description of the increases in GHG emissions from the proposed

facilities associated with the project. GHG emission calculations methods are also described,

and the resulting GHG emission rates are presented in Table 5-1 for each emission point.

Emissions calculations are included in Appendix A.

5.1 Combustion Units

The emissions calculations presented in Table A-1 of Appendix A identify all fuels that could

potentially be fired in each combustion unit. However, the emissions calculations are based on

firing the primary fuel for each unit, with all available Deethanizer Offgas and PSA Tail Gas

fired, and the balance of the fuel requirements made up by ethane and natural gas. Because

these fuels have different CO2 emission factors, the actual annual emission rate from each unit

will depend on the amount of each fuel fired. The maximum individual unit emission rates

shown in Table 5-1 are based on firing all available “worst case” fuel in each unit. As a result,

the sum of the individual unit emission limits exceeds the total emissions that are possible from

the plant as a whole. Thus, in addition to the individual emission limits, Enterprise is proposing

overall combustion unit caps for each GHG pollutant and total CO2e. This caps, calculated in

Table A-1, include all GHGs and CO2e from the Reactor Charge Heater, the WHB Stack (WHB

includes Gas Turbines, Regeneration Air Heater, Reactor VOC, Coke Burn, and WHB Duct

Burners), and the Auxiliary Boilers.

5.1.1 Reactor Charge Heater

The Reactor Charge Heater (HR15.101) will be fired primarily with Deethanizer Offgas. The

heater will also be capable of burning ethane and natural gas. Under normal conditions,

sufficient Deethanizer Offgas will be generated within the process to provide all required fuel for

the heater. Deethanizer Offgas and ethane result in higher CO2 emissions than natural gas;

therefore, the GHG emissions calculations for this unit are based on firing Deethanizer Offgas.

As can be seen from the emission factors presented in Table A-1 of Appendix A, Deethanizer

Offgas and ethane, have virtually identical GHG emission factors (lb/mmBtu basis). Annual

GHG emissions were calculated based on the maximum fuel firing rate of the heater occurring

continuously (8,760 hr/yr) all year. CO2 emissions were calculated based on the carbon content

of the Deethanizer Offgas using Equation C-5 in 40 CFR Part 98, Subpart C. Emissions of CH4

5-2

and N2O were calculated from emission factors from Table C-2 of Appendix A to 40 CFR Part

98, Subpart C.

5.1.2 Waste Heat Boiler (WHB)

Several facilities will contribute GHG emissions to the WHB. These include the Regeneration

Air Heater (HR15.102) combustion products, VOC from the Reactors that is converted to CO2

by oxidation catalyst beds, carbon from decoking of the reactor catalysts that is converted to

CO2 by the oxidation catalyst beds, Regeneration Air Gas Turbine (GT26.101A and GT26.101B)

combustion products, and WHB Duct Burners (HR15.103) combustion products. The

Regeneration Air Heater will primarily burn PSA Tail Gas and ethane or natural gas, but will also

be capable of burning Deethanizer Offgas. The Gas Turbines will be fired exclusively with

natural gas, and the WHB Duct Burners will be fired primarily with natural gas and ethane but

will be capable of firing Deethanizer Offgas and PSA Tail Gas. LTRU Offgas can be burned in

the Regeneration Air Heater and WHB Duct Burners; however, this only occurs when the PSA

Unit down, which is an upset condition. LTRU Offgas is primarily hydrogen, which results in

less emissions than other fuels. Under normal operating conditions, this stream is the feed to

the PSA Unit. For these reasons, none of the emission limits are based on combusting LTRU

Offgas. The calculations of the emissions from each facility that will exhaust through the WHB

Stack are described below.

5.1.2.1 Combustion Turbines

There will be two combustion turbines constructed for the project, (GT26.101A and GT26.101B).

The turbines will be used to compress the air used for reactor regenerations. Natural gas will be

the only fuel fired in the combustion turbines. Annual GHG emissions were calculated based on

the projected annual average fuel firing rate of each turbine. CO2 emissions were calculated

based on the carbon content of the natural gas using Equation C-5 in 40 CFR Part 98, Subpart

C. Emissions of CH4 and N2O were calculated from emission factors from Table C-2 of

Appendix A to 40 CFR Part 98, Subpart C.

5.1.2.2 Regeneration Air Heater

The Regeneration Air Heater (HR15.102) will normally be fired with all available PSA offgas with

the remainder of the heat input from either ethane or natural gas. Deethanizer Offgas may also

be fired in the heater. Annual GHG emissions were calculated based on the projected annual

5-3

average fuel firing rate of the heater. The emissions are base on burning all available PSA Tail

Gas and the balance of the fuel being Deethanizer Offgas and Ethane. CO2 emissions were

calculated based on the carbon content of each fuel using Equation C-5 in 40 CFR Part 98,

Subpart C. Emissions of CH4 and N2O were calculated from emission factors from Table C-2 of

Appendix A to 40 CFR Part 98, Subpart C.

5.1.2.3 WHB Duct Burner

The WHB will include a supplemenatally fired duct burner (HR15.103) that will be fired as

needed to provide for plant steam requirements. The duct burner will be fired primarily with

ethane or natural gas, but will also be capable of firing Deethanizer Offgas and PSA Tail Gas.

Maximum emissions occur from firing Deethanizer Offgas and/or ethane; therefore, the

emission limits were calculated based on firing Deethanizer Offgas. Annual GHG emissions

were calculated based on the projected annual average firing rate of the duct burner. CO2

emissions were calculated based on the carbon content of the fuels using Equation C-5 in 40

CFR Part 98, Subpart C. Emissions of CH4 and N2O were calculated from emission factors

from Table C-2 of Appendix A to 40 CFR Part 98, Subpart C.

5.1.2.4 Reactor Air Effluent and Ejector

VOC from the reactors is carried over in the Regeneration Air that enters the WHB. This VOC is

treated in a catalytic oxidation bed that converts the VOC to CO2. The catalytic oxidation bed

will be designed with a VOC destruction efficiency of at least 98.2%. CO2 emissions were

conservatively calculated assuming 100% destruction (conversion to CO2). Stoichiometrically,

production of CO2 from the oxidation of the VOC in the oxidation catalyst bed is identical to the

production of CO2 from combustion of carbon fuels. Therefore, CO2 emissions were calculated

based on the carbon content of the VOC using Equation C-5 in 40 CFR Part 98, Subpart C.

5.1.2.5 Decoke

CO2 emissions will be produced during periodic oxidation of the coke that builds up on the

catalyst. The emission rate is based on an estimate from the engineering design firm for the

project. These emissions are part of the Reactor Regeneration Effluent that is a contributor to

the combined WHB stack exhaust.

5-4

5.1.3 Auxiliary Boilers

The two Auxiliary Boilers (BO10.103A and BO10.103B) will normally operate at a very low

standby rate and will only be fully fired to provide steam when the primary units are down. The

Auxiliary Boilers will be fired primarily with ethane or natural gas, but will also be capable of

firing Deethanizer Offgas and PSA Tail Gas. Maximum emissions occur from firing Deethanizer

Offgas and/or ethane; therefore, the emission limits were calculated based on firing Deethanizer

Offgas. Annual GHG emissions were calculated based on firing the boilers at full load for 310

hour/yr each and at standby rates for the remainder of the year. CO2 emissions were calculated

based on the carbon content of the fuels using Equation C-5 in 40 CFR Part 98, Subpart C.

Emissions of CH4 and N2O were calculated from emission factors from Table C-2 of Appendix A

to 40 CFR Part 98, Subpart C.

5.1.4 Combustion Unit Emissions Caps

The combustion unit emissions caps which include all emissions from the facilities described

above were calculated based on the total combined annual heat input of all units. The

calculations of the caps are shown in Table A-1. The firing rates of each fuel used to provide

the total plant heat input were based on firing all produced Deethanizer Offgas and PSA Tail

Gas, firing natural gas in the combustion turbines, and the balance of the heat input being

provided by ethane. CO2 emissions were then calculated based on the carbon content of each

fuel using Equation C-5 in 40 CFR Part 98, Chapter C. Emissions of CH4 and N2O were

calculated from emission factors from Table C-2 of Appendix A to 40 CFR Part 98, Subpart C.

The CO2 from decoking and the oxidation of the Reactor VOC calculated as described in

Sections 5.1.2.4 and 5.1.2.5 were also added to the cap since this CO2 will be emitted through

the WHB Stack.

5.2 Flare Emissions

The new PDH Unit will have process vents that will be routed to a new flare (SK25.801) for

control. These process streams contain VOCs that when combusted by the flare produce CO2

emissions. Natural gas used as assist gas to maintain the minimum heating value required for

complete combustion also contains hydrocarbons, primarily methane, that also produce CO2

emissions when burned. Any unburned methane from the flare will also be emitted to the

atmosphere, and small quantities of N2O emissions can result from the combustion process.

Emissions of these pollutants were calculated based on the carbon content of the waste

streams sent to the flare and of the natural gas used for assist with the same equations and

5-5

emission factors from 40 CFR Part 98 that were used for the gas fired heaters. These

equations and factors were applied to the maximum projected annual waste gas and natural gas

flow rates to the flare. The calculations are shown in Table A-3.

5.3 Process Fugitive Emissions

Fugitive (equipment leak) emissions of methane will occur from the new natural gas and

process gas piping components (FUG-NGAS and FUG-PDH). The 28LAER leak detection and

repair (LDAR) program will be applied to the new VOC components associated with the PDH

Project. In addition, all flanges and connectors will be monitored quarterly using the same leak

detection level used for valves. All emissions calculations utilize current TCEQ factors and

methods in the TCEQ’s Air Permit Technical Guidance for Chemical Sources: Equipment Leak

Fugitives, October 2000. Each fugitive component was classified first by equipment type (valve,

pump, relief valve, etc.) and then by material type (gas/vapor, light liquid, heavy liquid).

Uncontrolled emission rates were obtained by multiplying the number of fugitive components of

a particular equipment/material type by the appropriate SOCMI emission factor. To obtain

controlled fugitive emission rates, the uncontrolled rates were multiplied by a control factor,

which was determined by the 28LAER LDAR program. The methane emissions were then

calculated by multiplying the total controlled emission rate by the weight percent of methane in

the natural gas and process gas. The calculations are shown in Table A-4.

5.4 Diesel Engines

There will be two diesel fired engines (PM18.803 and PM18.850C) used for emergency

purposes only. The engines will be used to drive fire water and raw water pumps. The

permitted emissions are based only on firing of the engines as required for scheduled testing to

insure operability, which will not exceed 52 hours per year each. Emissions were calculated

from emission factors for No. 2 distillate fuel in Tables C-1 and C-2 of Appendix A to 40 CFR

Part 98, Subpart C. The calculations are shown in Table A-5.

EPN

CO2

Emission Rate (tpy)

CH4

Emission Rate (tpy)

N2O Emission Rate (tpy)

CO2e Emission Rate (tpy)

HR15.101 Reactor Charge Heater 280,168 12.99 2.54 281,229

DW37.101 Waste Heat Boiler Burner 19,522 0.98 0.20 19,603

Regeneration Air Heater 650,704 23.89 4.25 652,523

Regen Air Comp. Gas Turbine A 124,897 2.32 0.23 125,018

Regen Air Comp. Gas Turbine B 124,897 2.32 0.23 125,018

VOC from Reactors 5,580 - - 5,580

Coke Burn 60,000 - - 60,000

BO10.103A Auxiliary Boiler A

BO10.103B Auxiliary Boiler B1,276,248 64.31 12.86 1,281,586

FUG-PDH Process Fugitives - 0.25 - 5

FUG-NGAS Nat. Gas Pipeline Fugitives - 13.04 - 274

SK25.801 Process Flare, Routine 2,818 0.04 0.01 2,821

Process Flare, MSS 4,426 0.16 0.03 4,439

PM18.803 Fire Water Pump Engine 16 0.0007 0.0001 16

PM18.850C Raw Water Pump Engine 8 0.0003 0.0001 8 1,283,517 77.79 12.90 1,289,149

Table 5-1 Proposed GHG Emission Limits

Description

Total GHG Emissions

16,389

Combustion Unit Cap

16,321 0.82 0.16

Individual Combustion Unit Limits

Other

5-6

6-1

Section 6 Best Available Control Technology

PSD regulations require that the best available control technology (BACT) be applied to each

new and modified facility that emits an air pollutant for which a significant net emissions

increase will occur from the source. The only PSD pollutant addressed in this permit application

is GHG. The new facilities associated with the project that emit GHGs include the following:

Reactor Charge Heater (HR15.101)

Regeneration Air Heater (HR15.102)

Waste Heat Boiler Duct Burner (HR15.103)

Two Combustion Turbines (GT26 101A and GT26 101A B),

Two Auxiliary Boilers (BO10.103A and BO10.103B)

Process Fugitives (FUG-PDH and FUG-NGAS)

Process Flare (SK25.801)

Two Emergency Use Diesel Engines (PM18.803 and PM18.850C).

BACT applies to each of these new sources of GHG emissions.

The U.S. EPA-preferred methodology for a BACT analysis for pollutants and facilities subject to

PSD review is described in a 1987 EPA memo (U.S. EPA, Office of Air and Radiation

Memorandum from J.C. Potter to the Regional Administrators, December 1, 1987). This

methodology is to determine, for the emission source in question, the most stringent control

available for a similar or identical source or source category. If it can be shown that this level of

control is technically or economically infeasible for the source in question, then the next most

stringent level of control is determined and similarly evaluated. This process continues until the

BACT level under consideration cannot be eliminated by any substantial or unique technical,

environmental, or economic objections. In addition, a control technology must be analyzed only

if the applicant opposes that level of control.

In an October 1990 draft guidance document (New Source Review Workshop Manual (Draft),

October 1990), EPA set out a 5-step process for conducting a top-down BACT review, as

follows:

1) Identification of available control technologies;

2) Technically infeasible alternatives are eliminated from consideration;

6-2

3) Remaining control technologies are ranked by control effectiveness;

4) Evaluation of control technologies for cost-effectiveness, energy impacts, and environmental effects in order of most effective control option to least effective; and

5) Selection of BACT.

In its PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011), EPA

reiterates that this is also the recommended process for permitting of GHG emissions under the

PSD program. As such, this BACT analysis follows the top-down approach.

6.1 Reactor Charge Heater

6.1.1 Step 1 – Identification of Potential Control Technologies

To maximize thermal efficiency at the Mont Belvieu Complex, the proposed heaters will be

designed to achieve high thermal efficiencies, which minimize GHG emissions. The Reactor

Charge Heater will be designed to achieve a 90% thermal efficiency. These and other

potentially applicable technologies to minimize GHG emissions from the heater include the

following:

Periodic Tune-up – Periodically tune-up of the heater to maintain optimal thermal efficiency.

Heater Design – Good heater design to maximize thermal efficiency,

Heater Air/Fuel Control – Monitoring of oxygen concentration in the flue gas to be used to control excess air on a continuous basis for optimal efficiency.

Waste Heat Recovery – Use of heat recovery from the heater exhaust to preheat the heater combustion air or other streams.

Use of Low Carbon Fuels – Fuels vary in the amount of carbon per btu, which in turn affects the quantity of CO2 emissions generated per unit of heat input. Selecting low carbon fuels is a viable method of reducing GHG emissions.

CO2 Capture and Storage – Capture and compression, transport, and geologic storage of the CO2.

A RACT/BACT/LAER Clearinghouse (RBLC) search was also conducted in an attempt to

identify BACT options that have been implemented or proposed for other similar gas fired

combustion facilities. The results of this search are presented in Appendix B. No additional

technologies were identified. The control methods identified in the search were limited to the

first three options listed above (tune-ups, good design, and good combustion control and

operation). Information from Energy Efficiency Improvement and Cost Saving Opportunities for

the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Managers

6-3

(Environmental Energy Technologies Division, University of California, sponsored by USEPA,

June 2008) was also used in the preparation of this analysis.

6.1.2 Step 2 – Elimination of Technically Infeasible Alternatives

All options identified in Step 1 are considered technically feasible. Carbon capture and

sequestration (CCS) is not considered to be a viable alternative for controlling GHG emissions

from gas fired facilities. However, for completeness, this control option is included in the

remainder of this analysis, and the reasons that it is not considered viable are discussed in

Section 6.1.4.

6.1.3 Step 3 – Ranking of Remaining Technologies Based on Effectiveness

The remaining technologies applicable to the proposed heater design in order of most effective

to least effective include:

Use of low carbon fuels (up to 100% for fuels containing no carbon),

CO2 capture and storage (up to 90%),

Heater Design (up to 10%),

Air and Fuel Control (5 - 25%),

Periodic tune-up (up to 10% for boilers; information not found for heaters), and

Waste heat recovery (variable).

Virtually all GHG emissions from fuel combustion result from the conversion of the carbon in the

fuel to CO2. Fuels used in industrial processes and power generation typically include coal, fuel

oil, natural gas, and process fuel gas. Of these, natural gas is typically the lowest carbon fuel

that can be burned, with a CO2 emission factor in lb/mmbtu about 55% of that of sub bituminous

coal. Process fuel gas is a byproduct of chemical process, which typically contains a higher

fraction of longer chain carbon compounds than natural gas and thus results in more CO2

emissions. Table C-2 in 40 CFR Part 98 Subpart C, which contains CO2 emission factors for a

variety of fuels, gives a CO2 factor of 59 kg/MMBtu for fuel gas compared to 53.02 kg/MMBtu for

natural gas. Of over 50 fuels identified in Table C-2, coke oven gas, with a CO2 factor of 46.85

kg/MMBtu, is the only fuel with a lower CO2 factor than natural gas, and is not viable fuel for the

proposed heaters, as the Mount Belvieu Complex does not contain coke ovens. Although Table

C-2 includes a typical CO2 factor of 59 kg/MMBtu for fuel gas, fuel gas composition is highly

dependent on the process from which the gas is produced. Some processes produce

significant quantities of hydrogen, which produces no CO2 emissions when burned. Thus, use

6-4

of a completely carbon-free fuel such as 100% hydrogen, has the potential of reducing CO2

emissions by 100%.

CO2 capture and storage is capable of achieving 90% reduction of produced CO2 emissions and

thus is considered to be the most effective control method.

Good heater design, air and fuel control, and periodic tune-ups are all considered effective and

have a range of efficiency improvements which cannot be directly quantified; therefore, the

above ranking is approximate only. The estimated efficiencies were obtained from Energy

Efficiency Improvement and Cost Saving Opportunities for the Petrochemical Industry: An

ENERGY STAR Guide for Energy Plant Managers (Environmental Energy Technologies

Division, University of California, sponsored by USEPA, June 2008). This report addressed

improvements to existing energy systems as well as new equipment; thus, the higher end of the

range of stated efficiency improvements that can be realized is assumed to apply to the existing

(older) facilities, with the lower end of the range being more applicable to new heater designs.

Heat recovery involves the use of heat exchangers to transfer the excess heat that may be

contained in one process or product stream to pre-heat another stream. Pre-heating of feed

streams in this manner reduces the heat requirement of the downstream process unit (e.g., a

distillation column) which reduces the heat required from process heaters. Where the product

streams require cooling, this practice also reduces the energy required to cool the product

stream. The Charge Heater will be designed for 90% thermal efficiency, and additional heat

recovery is not practical. However, heat exchange coils will be included in the convection

section to pre-heat Waste Heat Boiler feedwater.

6.1.4 Step 4 – Evaluation of Control Technologies in Order of Most Effective to Least Effective

Carbon Capture and Sequestration. As stated in Section 6.1.2, carbon capture and sequestration

(CCS) is not considered to be a viable alternative for controlling GHG emissions from gas fired

facilities. This conclusion is supported by the BACT example for a natural gas fired boiler in Appendix

F of EPA’s PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011). In the EPA

example, CCS is not even identified as an available control option for natural gas fired facilities. Also,

on pages 33 and 44 of the Guidance Document, it states:

“For the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add-on pollution control

technology that is available for large CO2-emitting facilities including fossil fuel-fired power plants and

6-5

industrial facilities with high-purity CO2 streams (e.g., hydrogen production, ammonia production,

natural gas processing, ethanol production, ethylene oxide production, cement production, and iron

and steel manufacturing). For these types of facilities, CCS should be listed in Step 1 of a top-down

BACT analysis for GHGs.”

The CO2 streams included in this permit application are similar in nature to the gas-fired industrial

boiler in the EPA Guidance Appendix F example and are dilute streams, and thus are not among the

facility types for which the EPA guidance states CCS should be listed in Step 1. Although the

proposed facility is not one of the listed facility types for which CCS should be considered, it was

further evaluated for the project to ensure that the analysis was complete.

Enterprise has performed an order of magnitude cost analysis for CCS applied to the combustion

units addressed in this permit application. The results of the analysis, presented in Table 6-1, show

that the cost of CCS for the project would be approximately $104 per ton of CO2 controlled, which is

not considered to be cost effective for GHG control. This equates to a total cost of about

$119,000,000 per year all combustion units included at the proposed plant. The estimated total

capital cost of the PDH unit is $1,300,000,000. Based on a 7% interest rate, and 20 year equipment

life, this cost equates to an annualized cost of about $123,000,000. Thus, the annualized cost of

CCS would be about the same as the cost of the PDH plant alone; which far exceeds the threshold

that would make CCS economically viable for the project.

There are additional negative impacts associated with use of CCS for the facilities. The additional

process equipment required to separate, cool, and compress the CO2 would require a significant

additional power and energy expenditure. This equipment would include amine units, cryogenic units,

dehydration units, and compression facilities. The power and energy must be provided from

additional combustion units, including heaters, engines, and/or combustion turbines. Electric driven

compressors could be used to partially eliminate additional emissions from the Mont Belvieu

Complex, but significant additional GHG emissions, as well as additional criteria pollutant (NOx, CO,

VOC, PM, SO2) emissions, would occur from the associated power plant that produces the electricity.

The additional GHG emissions resulting from additional fuel combustion would either further increase

the cost of the CCS system if the emissions were also captured for sequestration or reduce the net

amount GHG emission reduction, making CCS even less cost effective than shown in Table 6-1.

6-6

Based on both the excessive cost effectiveness in $/ton of GHG emissions controlled and the inability

of the project to bear the high cost and the associated negative environmental and energy impacts,

CCS is rejected as a control option for the proposed project.

Heater Design. New heaters can be designed with efficient burners, more efficient heat transfer,

state-of-the-art refractory and insulation materials in the heater walls, floor, and other surfaces to

minimize heat loss and increase overall thermal efficiency. The function and near steady state

operation of the heater allows them to be designed to achieve “near best” thermal efficiency.

Air and Fuel Controls. Some amount of excess air is required to ensure complete fuel combustion,

minimize emissions, and for safety reasons. More excess air than needed to achieve these

objectives reduces overall heater efficiency. Manual or automated air fuel controls are used to

optimize these parameters and maximize the efficiency of the combustion process.

Periodic Heater Tune-ups. Periodic tune-ups of the heater include:

Preventive maintenance check of fuel gas flow meters annually,

Preventive maintenance check of excess oxygen analyzers quarterly,

Cleaning of burner tips on an as-needed basis, and

Cleaning of convection section tubes on an as-needed basis.

These activities insure maximum thermal efficiency is maintained; however, it is not possible to

quantify an efficiency improvement, although convection cleaning has shown improvements in

the 0.5 to 1.5% range.

Use of Low Carbon Fuel. Several low carbon fuels are potentially available for use in the PDH

plant combustion units. The discussion below applies to all combustion units within the

proposed PDH Unit.

Hydrogen. Hydrogen is a byproduct of the proposed PDH process. The PDH Unit will include

a PSA Unit that will purify the hydrogen byproduct. Enterprise’s business plan calls for selling

the hydrogen as a product; therefore, it is not available for use as a fuel at the plant. The most

common industrial use of hydrogen in the Gulf Coast area is for the desulfurization of crude oil

in petroleum refineries. Hydrogen for this use is typically produced at refineries in steam

methane reformers (SMR), which produce hydrogen from methane, producing a large CO2

stream that is exhausted to the atmosphere. Thus, the hydrogen product from the proposed

PDH Unit will displace an equivalent amount of hydrogen production from refinery SMRs,

6-7

eliminating the associated CO2 emissions. Thus, although using the hydrogen byproduct as fuel

within the PDH Unit would reduce CO2 emissions from the proposed plant, there would be a

corresponding increase in CO2 emissions from the production of hydrogen elsewhere, resulting

in no net “global” reduction of CO2 emissions. Unlike criteria pollutants, GHG emission impacts

are “global,” and there is no benefit in simply displacing the emissions to another location. For

this reason together with Enterprise’s business plan to produce hydrogen as a marketable

product, use of the hydrogen byproduct as a fuel at the PDH Unit is not considered to be a

viable option for reducing global CO2 emissions.

PSA Tail Gas. Tail Gas from the PSA Unit will contain a significant fraction (about 60% by

volume) of hydrogen. The CO2e emission factor for this Tail Gas will average about 96

lb/mmBtu, compared to about 118 lb/mmBtu for the natural gas that is available for use at the

plant. About 2,200,000 mmBtu/yr of PSA Tail gas will be produced at the PDH plant capacity.

This corresponds to a potential reduction in CO2e emissions of about 23,000 tpy compared to

firing an equivalent amount of natural gas.

Deethanizer Offgas. Deethanizer Offgas will also be produced in the PDH Unit. This process

gas, which is primarily ethane and ethylene, has a CO2e emission factor of about 131 lb/mmBtu,

which is only about 11% higher than natural gas. Thus this fuel is also considered a low carbon

fuel when compared to liquid and solid fuels. If this offgas is not burned as fuel at the PDH Unit,

the only other alternative means of disposal is destruction in a flare, which would result in the

same amount of CO2e emissions in addition to the CO2e emissions from the natural gas that

would replace it as a fuel. As such, use of the Deethanizer Offgas as fuel is an effective means

of reducing overall plant GHG emissions compared to the alternative of flaring the gas.

Ethane. Ethane is also an available fuel for the PDH Unit. There is currently an over-

abundance of ethane being produced from natural gas production facilities. Some of this

ethane can be used as feedstock to ethylene plants, but excess ethane still exists. The

alternatives for use or disposal of this excess ethane include flaring it, removing less of it from

natural gas, and using it as a fuel source at industrial facilities (such as the proposed PDH Unit).

All of these alternatives result in the same amount of CO2 emissions when the ethane is

ultimately burned. Flaring is the least desirable alternative as no heat benefit is gained, and

there would be additional CO2 emissions from combustion of the natural gas that it would

otherwise replace. Ethane has a CO2e emission factor of about 118 lb/mmBtu, which is about

the same as the Deethanizer Offgas that will be produced in the PDH Unit. Thus, using excess

6-8

ethane available on the market as fuel in place of natural gas results in only about 11% more

CO2e emissions from the plant compared to an equivalent amount of natural gas, and no net

increase in global CO2e emissions. Ethane is also a very clean burning fuel with respect to

criteria pollutants and thus has minimal environmental impact compared to other fuels.

Natural Gas. Other than PSA Tail Gas, natural gas is the lowest carbon fuel available for use

in the proposed heater. Natural gas is readily available at the Mont Belvieu Complex and is

currently considered a very cost effective fuel alternative. Natural gas is also a very clean

burning fuel with respect to criteria pollutants and thus has minimal environmental impact

compared to other fuels.

6.1.5 Step 5 – Selection of BACT

Air and fuel controls, efficient heater design, and tune-ups performed as needed are currently

utilized on existing heaters at the Mont Belvieu Complex to maximize efficiency and thus reduce

GHG emissions. These control practices are also included in the design of the Charge Heater

and are thus part of the selected BACT. These technologies and additional BACT practices

proposed for the Charge Heater are listed below:

Use of a combination of low carbon fuels. A combination of PSA Tail Gas, Deethanizer Offgas, ethane, and natural gas will be fired in the proposed PDH Unit combustion units. This will result in an overall CO2e emission rate of about 125 lb/mmBtu of fuel burned. This emission rate is comparable to burning 100% natural gas, and results in lower “global” CO2e emissions compared to burning 100% natural gas and disposing of the offgases by other methods.

Determine CO2e emissions from the Reactor Charge Heater based on metered fuel consumption and standard emission factors and/or fuel composition and mass balance.

Good heater design to maximize heat transfer efficiency to evenly heat the propane feed and reduce heat loss. Insulating material, such as ceramic fiber blankets of various thickness and density, will be used where feasible on all heater surfaces.

Demonstrate heater efficiencies by monitoring the exhaust temperature, fuel temperature, ambient temperature, and excess oxygen. Thermal efficiency will be calculated for each operating hour from these parameters using accepted API methods. Charge Heater efficiency of greater than 85% will be maintained on a 12-month rolling average basis, excluding malfunction and maintenance periods.

The heater will include heat exchange coils in the convection section to pre-heat the boiler feedwater used in the Waste Heat Boiler.

Install, utilize, and maintain an automated air and fuel control system to maximize combustion efficiency of the heater.

Clean heater burner tips and convection tubes as needed.

6-9

Calibrate and perform preventive maintenance on the fuel flow meter once per year and excess oxygen analyzer once per quarter.

6.2 Regeneration Air Heater


To maximize thermal efficiency at the Mont Belvieu Complex, the proposed heaters are

designed to achieve high thermal efficiencies, which minimize GHG emissions. The

Regeneration Air Heater will utilize duct burners, and the heater will be designed to maximize

thermal efficiency. These and other potentially applicable technologies to minimize GHG

emissions from the heater include the following:

Periodic Tune-up – Periodically tune-up of the heater to maintain optimal thermal efficiency.

Heater Design – Good heater design utilizing refractory to maximize thermal efficiency,

Waste Heat Recovery – Use of heat recovery from the heater exhaust and a waste heat boiler to produce steam for use at the site.

Use of Low Carbon Fuels – Use of low carbon fuels at the plant were addressed in Section 6.1 and are not addressed separately for the Regeneration Air Heater.

CO2 Capture and Storage – Capture and compression, transport, and geologic storage of the CO2 (This option is evaluated in detail in Section 6.1.4 for the plant as whole and was eliminated based on cost and is thus not addressed further in this section).











All options identified in Step 1 are considered technically feasible.

6-10


The remaining technologies applicable to the proposed heater design in order of most effective


Waste heat recovery (variable),

Heater Design (up to 10%), and

Periodic tune-up (up to 10% for boilers; information not found for heaters).

Air is heated by the Regeneration Air Heater duct burners and used to regenerate the catalyst in

the reactors. The hot air from the reactors contains a large amount of usable heat energy, and

the proposed process is designed to recover and use this heat by routing the hot air through the

Waste Heat Boiler which provides the plant steam requirements. This is discussed in more

detail in Section 6.3.

Good heater design and periodic tune-ups are all considered effective and have a range of

efficiency improvements which cannot be directly quantified; therefore, the above ranking is

approximate only. The estimated efficiencies were obtained from Energy Efficiency

Improvement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY STAR

Guide for Energy Plant Managers (Environmental Energy Technologies Division, University of

California, sponsored by USEPA, June 2008). This report addressed improvements to existing

energy systems as well as new equipment; thus, the higher end of the range of stated efficiency

improvements that can be realized is assumed to apply to the existing (older) facilities, with the

lower end of the range being more applicable to new heater designs.


Heater Design. New heaters can be designed with efficient burners, more efficient heat transfer,

state-of-the-art refractory and insulation materials in the heater walls, floor, and other surfaces to


operation of the heater allows it to be designed to achieve “near best” thermal efficiency.

Periodic Heater Tune-ups. Periodic tune-ups of the heater include:


Preventive maintenance check of oxygen control analyzers quarterly,



6-11





Efficient heater design and tune-ups performed as needed are currently utilized on existing

heaters at the Mont Belvieu Complex to maximize efficiency and thus reduce GHG emissions.

These control practices are also included in the design of the Regeneration Air Heater and are

thus part of the selected BACT. These technologies and additional BACT practices proposed

for the heater are listed below:

Use of a combination of low carbon fuels. A combination of PSA Tail Gas, Deethanizer Offgas, ethane, and natural gas will be fired in the proposed PDH Unit combustion units, including the Regeneration Air Heater, to maintain a plantwide CO2e emission rate of about 125 lb/mmBtu.

Determine CO2e emissions from the Regeneration Air Heater based on metered fuel consumption and standard emission factors and/or fuel composition and mass balance.

Good heater design to maximize heat transfer efficiency and reduce heat loss. Insulating material, such as ceramic fiber blankets of various thickness and density, will be used where feasible on all heater surfaces.

Route hot spent regenerator air through Waste Heat Boiler to recover heat for steam production.

Install, utilize, and maintain an automated fuel control system to maximize combustion efficiency of the heater.

Clean heater burner tips as needed.

Calibrate and perform preventive maintenance on the fuel flow meter once per year.

6.3 Waste Heat Boiler


The Waste Heat Boiler (WHB) is the key heat energy efficiency feature of the proposed PDH

Unit design that will allow the plant to produce propylene with up to one-third less fuel

consumption than other production processes. The combustion products from the Regeneration

Air Heater and the Regeneration Air Compressor Combustion Turbines is routed through the

WHB to produce steam that is used internally in the PDH Unit. The WHB will include a gas-fired

duct burner that will be used for startup of the WHB and to provide supplemental heat as

6-12

needed to meet plant steam demand. These and other potentially applicable technologies to

minimize GHG emissions from the boilers include the following:

Good combustion practices via improved process controls.

Boiler Design – Good boiler design to maximize thermal efficiency,

Routine Boiler Maintenance - Periodically tune-up the boiler to maintain optimal thermal efficiency.

Waste Heat Recovery - The proposed boiler is a waste heat recovery unit that will obtain most of its required heat energy from waste heat.

Use of Low Carbon Fuels – Use of low carbon fuels at the plant were addressed in Section 6.1 and are not addressed separately for the WHB Duct Burners.














The remaining technologies applicable to the proposed boilers design in order of most effective


Waste Heat Recovery has primary energy source (>90%),

Boiler Design (up to 26%), and

Routine planned maintenance tune-up (up to 10% ).

Hot exhaust from the regeneration of the reactors and from the Regeneration Air Compressor

Turbine exhaust contains sufficient waste heat to provide over 90% of the heat input normally

6-13

required for steam produced in the WHB and is thus considered the most effective means of

reducing GHG emissions by eliminating the combustion of fuel that would otherwise be

required.

Good boiler design and periodic tune-ups are all considered effective and have a range of

efficiency improvements which cannot be directly quantified; therefore, the above ranking is

approximate only. The estimated efficiencies were obtained from Energy Efficiency

Improvement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY STAR

Guide for Energy Plant Managers (Environmental Energy Technologies Division, University of

California, sponsored by USEPA, June 2008). This report addressed improvements to existing

energy systems as well as new equipment; thus, the higher end of the range of stated efficiency

improvements that can be realized is assumed to apply to the existing (older) facilities, with the

lower end of the range being more applicable to new boiler designs.

Heat recovery involves the use of economizers to transfer the excess heat from the boiler flue

gases to the boiler feed water streams. Pre-heating of boiler feed water stream in this manner

reduces the heat requirement of the boilers.


Waste Heat Recovery. Rather than increasing boiler efficiency, this technology reduces potential

GHG emissions by reducing the required WHB duct burner firing rate, which can substantially reduce

overall plant energy requirements. Over 800 mmBtu/hr of waste heat energy from the Reactor

Regeneration Air Exhaust and Compressor Combustion Turbine Exhaust will be recovered in the

WHB and used to produce steam. On an annual average basis, the supplemental WHB duct burner

will only need to be fired at a rate of about 30 mmBtu/hr. Thus, over 95% of the heat energy required

for the PDH Unit steam demand will be provided from waste heat.

Boiler Design. New boilers can be designed with efficient burners, more efficient heat transfer,

state-of-the-art refractory and insulation materials in the boiler walls, floor, and other surfaces to


operation of the boilers allows them to be designed to achieve “near best” thermal efficiency.

Periodic Boiler Maintenance Tune-ups. Periodic tune-ups of the boilers include:


6-14







Use of the proposed WHB itself is the primary GHG BACT feature of the PDH Unit. Air/fuel

controls, efficient boiler design, and tune-ups performed as needed will also be included to

maximize efficiency and thus reduce GHG emissions. These technologies and additional BACT

practices proposed for the boilers are listed below:

Use of waste heat to provide over 95% of the WHB heat energy requirements.

Use of low carbon fuel. A combination of PSA Tail Gas, Deethanizer Offgas, ethane, and natural gas will be fired in the proposed PDH Unit combustion units, including the WHB Duct Burner, to maintain a plantwide CO2e emission rate of about 125 lb/mmBtu.

Determine CO2e emissions from the Waste Heat Boiler based on metered fuel consumption and standard emission factors and/or fuel composition and mass balance.

Good boiler design to maximize heat transfer efficiency and to reduce heat loss.

Install, utilize, and maintain an automated fuel control system to maximize combustion efficiency on the boilers.



Use of boiler feedwater pre-heated by the economizer in the Reactor Charge Heater.

6.4 Auxiliary Boilers


The Auxiliary Boilers will be designed to maximize thermal efficiency and will be designed to

operate in a very low (about 3% of full load firing rate) standby rate when not in use. These and

other potentially applicable technologies to minimize GHG emissions from the boilers include

the following:

Good combustion practices that include; improved process controls, reducing flue gas quantities, and reducing excess air.

Boiler Design – Good boiler design to maximize thermal efficiency,

6-15

Low standby operation,

Routine boiler maintenance - Periodically tune-up of the boilers to maintain optimal thermal efficiency.

Use of Low Carbon Fuels – Use of low carbon fuels at the plant were addressed in Section 6.1 and are not addressed separately for the Auxiliary Boilers.













The two auxiliary boilers, although of a size sufficient enough to consider use of a carbon

capture and sequestration (CCS) system, will only be in operation for short periods of time

during the year as backup boilers to the waste heat boiler. This makes the carbon capture and

sequestration process not technically feasible for the two auxiliary boilers. A cost analysis for

use of CCS at the proposed plant, included in Section 6.1, has also shown that CCS is not cost

effective.


The remaining technologies applicable to the proposed boilers design in order of most effective


Low Standby Operating Rate,

Boiler Design (up to 26%),

Air and Fuel Control (1% improvement for each 15% less excess air),

Routine planned maintenance tune-up (up to 10%).

6-16

The Auxiliary Boilers are projected to be needed for full use less than 4% (310 hr/yr) of the time;

however, they must be kept in a hot standby condition to allow them to be brought on line

quickly when needed. As such, the potential exists for the majority of the fuel consumption and

resulting GHG emissions to occur from standby operation. As such, designing the boilers to

operate at a very low standby firing rate is considered the most effective means of reducing

GHG emissions.

Good boiler design, excess oxygen control, and periodic tune-ups are all considered effective

and have a range of efficiency improvements which cannot be directly quantified; therefore, the

above ranking is approximate only. Due to the very low expected usage rate, typical energy

efficiency features used in boiler designs have minimal benefit for the proposed boilers.


Low Standby Operating Rate. Minimizing the standby firing rate to the maximum extent possible is

the most effective means of controlling GHG emissions as this operating mode will occur over 96% of

the time. There are no adverse environmental or economic impacts associated with this practice.

Boiler Design. New boilers can be designed with efficient burners, more efficient heat transfer,

state-of-the-art refractory and insulation materials in the boiler walls, floor, and other surfaces to


operation of the boilers allows them to be designed to achieve “near best” thermal efficiency.

Air and Fuel Controls. Some amount of excess air is required to ensure complete fuel combustion,

minimize emissions, and for safety reasons. More excess air than needed to achieve these

objectives reduces overall heater efficiency. Manual or automated air and fuel controls are used to

optimizes these parameters and maximize the efficiency of the combustion process.

Periodic Boiler Maintenance Tune-ups. Periodic tune-ups of the boilers include:


Preventive maintenance check of excess oxygen analyzers quarterly,



6-17





Designing the burners to operate at a low standby firing rate is proposed as the primary GHG

BACT method for the Auxiliary Boilers. Air and uel controls and efficient boiler design, and

tune-ups performed as needed are currently utilized on the existing fired equipment at the Mont

Belvieu Complex to maximize efficiency and thus reduce GHG emissions. These control

practices are also included in the design of the new boilers and are thus part of the selected

BACT. These technologies and additional BACT practices proposed for the boilers are listed

below:

The boilers will be designed to be operated at a standby firing rate of 14 mmBtu/hr each, which is about 3.3% of the boiler capacities. Although standby operation will constitute over 96% of the operating hours, the low firing rate will result in total annual standby fuel usage and GHG emissions that are less than the total annual fuel usage and GHG emissions from full load operation.

Use of low carbon fuel. A combination of PSA Tail Gas, Deethanizer Offgas, ethane, and natural gas will be fired in the proposed PDH Unit combustion units, including the Auxiliary Boilers, to maintain a plantwide CO2e emission rate of about 125 lb/mmBtu.

Determine CO2e emissions from the Auxiliary Boilers based on metered fuel consumption and standard emission factors and/or fuel composition and mass balance.

Good boiler design to maximize heat transfer efficiency and to reduce heat loss.

Install, utilize, and maintain an automated airand fuel control system to maximize combustion efficiency on the boilers.


Calibrate and perform preventive maintenance on the fuel flow meter once per year and excess oxygen analyzers as needed.

6.5 Combustion Turbines


To maximize thermal efficiency at the Mont Belvieu Complex, the proposed natural gas fired

turbines are designed to achieve high thermal efficiencies, which minimize GHG emissions.

The proposed new gas turbines are designed to maximize thermal efficiency. In addition, as

described in Section 6.3, the turbines will exhaust into the WHB, where the heat in the exhaust

will be recovered to the maximum extent practical to produce steam. These and other

6-18

potentially applicable technologies to minimize GHG emissions from the gas turbines include

the following:

Good combustion practices via improved process controls and reducing excess air.

Turbine Design – Good design to maximize thermal efficiency,

Routine Maintenance - Periodically tune-up to maintain optimal combustion and thermal efficiency.

Waste Heat Recovery – Use of heat recovery from the turbine exhausts in the WHB to produce steam for use at the site.

Uses of low carbon fuels - Fuels vary in the amount of carbon per btu, which in turn affects the quantity of CO2 emissions generated per unit of heat input. Selecting low carbon fuels is a viable method of reducing GHG emissions.

CO2 Capture and Storage – Capture and compression, transport, and geologic storage of the CO2. (This option is evaluated in detail in Section 6.1.4 for the plant as whole and was eliminated based on cost and is thus not addressed further in this section).










Waste heat recovery from the turbine exhaust is included in the process design and has been

addressed in Section 6.3 of the BACT analysis for the WHB and is not address further in this

section.




The remaining technologies applicable to the proposed turbines in order of most effective to

least effective include:

Use of low carbon alternative fuels,

6-19

Turbine Design,

Good Combustion Practices,

Routine planned maintenance tune-up (up to 10%).

Natural gas is the lowest carbon fuel available for use in the proposed turbines. Use of other

gaseous fuels are not recommended by the turbine vendor.

Good turbine design, good combustion practices and periodic tune-ups are all considered

effective and have a range of efficiency improvements which cannot be directly quantified;

therefore, the above ranking is approximate only.


Turbine Design. New turbines can be designed with efficient burners, more efficient heat transfer, to

increase overall thermal efficiency. The function and near steady state operation of the turbines

allows them to be designed to achieve “near best” thermal efficiency.

Good Combustion Practices. Some amount of excess air is required to ensure complete fuel

combustion, minimize emissions, and for safety reasons. More excess air than needed to achieve

these objectives reduces overall heater efficiency. Air to fuel ratios are tuned periodically to optimize

these parameters and maximize the efficiency of the combustion process.

Periodic Maintenance Tune-ups. Periodic tune-ups of the turbines include:


Periodically tune the air flows, and

Cleaning of burner tips on an as-needed basis,




Use of Low Carbon (Natural Gas) Fuel. Natural gas is the lowest carbon fuel available for use

in the proposed turbines. Natural gas is readily available at the Mont Belvieu Complex and is

currently considered a very cost effective fuel alternative. Natural gas is also a very clean

burning fuel with respect to criteria pollutants and thus has minimal environmental impact

compared to other fuels. Offgas and other fuels that will be used for the heaters and boilers are

6-20

not recommended by the turbine vendors, and turbine performance and criteria pollutant

emission limits cannot be guaranteed for fuels other than natural gas.


Good combustion practices, efficient boiler design, and tune-ups performed as needed are

currently utilized on the existing turbines at the Mont Belvieu Complex to maximize efficiency

and thus reduce GHG emissions. These control practices are also included in the design of the

new turbines and are thus part of the selected BACT. These technologies and additional BACT

practices proposed for the turbines are listed below:

Waste Heat Recovery. Recovering waste heat from the turbine exhaust to the maximum extent possible in the WHB to produce steam for use at the plant is a keep plant energy feature as described in Section 6.1

Use of low carbon fuel (natural gas). Natural gas will be the only fuel fired in the proposed turbines.

Determine CO2e emissions from the turbines based on metered fuel consumption and standard emission factors and/or fuel composition and mass balance.

Good turbine design to maximize heat transfer efficiency and to reduce heat loss.


6.6 Flare

GHG emissions, primarily CO2, are generated from the combustion of waste gas streams from

the proposed units and assist natural gas used to maintain the required minimum heating value

to achieve adequate destruction.


The only viable control option for reducing GHG emissions from flaring is minimizing the

quantity of flared waste gas and natural gas to the extent possible. The technically viable

options for achieving this include:

Flaring minimization – minimize the duration and quantity of flaring to the extent possible through good engineering design of the process and good operating practice.

Proper operation of the flare – use of flow and composition monitors to accurately determine the optimum amount of natural gas required to maintain adequate VOC destruction in order to minimize natural gas combustion and the resulting CO2.

Use of a thermal oxidizer in lieu of a flare.

6-21


Both flaring minimization and proper operation of the flare are considered technically feasible.

One of the primary reasons that a flare is considered for control of VOC in the process vent

streams is that it can also be used for emergency releases. Although every possible effort is

made to prevent such releases, they can occur, and the design must allow for them. A thermal

oxidizer is not capable of handling the sudden large volumes of vapor that could occur during an

upset release. A thermal oxidizer would also not result in a significant difference in GHG

emissions compared to a flare. Thus, although a thermal oxidizer may be a more effective

control alternative than a flare for VOC emissions, it does nothing to reduce GHG emissions.

For this reason, even if a thermal oxidizer was used for control of routine vent streams, the flare

would still be necessary and would require continuous burning of natural gas in the pilots, which

add additional CO2, NOx, and CO emissions.

For these reasons, use of either a thermal oxidizer is rejected as technically infeasible for the

proposed project.


Flare minimization and proper operation of the flare are potentially equally effective but have

case-by-case effectiveness that cannot be quantified to allow ranking.


Use of an analyzer(s) to determine the heating value of the flare gas to allow continuous

determination of the amount of natural gas needed to maintain a minimum heating value of 300

Btu/scf to insure proper destruction of VOCs ensures that excess natural gas is not

unnecessarily flared. This added advantage of reducing fuel costs makes this control option

cost effective as both a criteria pollutant and GHG emission control option. There are no

negative environmental impacts associated with this option. Proper design of the process

equipment to minimize the quantity of waste gas sent to the flare also has no negative economic

or environmental impacts.


Enterprise proposes use of both identified control options to minimize GHG emissions from

flaring of process vents from the proposed facilities. Flare system analyzers will be used to

6-22

continuously monitor the combined waste gas stream sent to the flare from the proposed and

other existing facilities to determine the quantity of natural gas required to maintain a minimum

heating value of 300 Btu/scf and also to limit the quantity of natural gas use only what is needed

to maintain 300 Btu/scf. The efficient use of natural gas will avoid the production of both

unnecessary GHG emissions as well as criteria pollutants.

6.7 Fugitives (EPNs FUG-PDH & FUG-NGAS)

Hydrocarbon emissions from leaking piping components, (fugitives), in the process (EPN FUG-

PDH) and in the natural gas pipeline (EPN FUG-NGAS) associated with the proposed project

include methane, a GHG. The additional methane emissions from fugitives have been

conservatively estimated to be 5 tpy as CO2e from EPN FUG-PDH and 274 tpy as CO2e from

EPN FUG-NGAS as CO2e. This is a negligible contribution to the total GHG emissions;

however, for completeness, they are addressed in this BACT analysis.


The only identified control technology for a process fugitive emission of CO2e is use of a leak

detection and repair (LDAR) program. LDAR programs vary in stringency as needed for control

of VOC emissions; however, due to the negligible amount of GHG emissions from fugitives,

LDAR programs would not be considered for control of GHG emissions alone. As such,

evaluating the relative effectiveness of different LDAR programs is not warranted.


LDAR programs are a technically feasible option for controlling process fugitive GHG emissions.


As stated in Step 1, this evaluation does not compare the effectiveness of different levels of

LDAR programs.


Although technically feasible, use of an LDAR program to control the negligible amount of GHG

emissions that occur as process fugitives is clearly cost prohibitive. However, if an LDAR

program is being implemented for VOC control purposes, it will also result in effective control of

the small amount of GHG emissions from the same piping components. Enterprise uses

6-23

TCEQ’s 28LAER LDAR program at the Mont Belvieu Complex to minimize process fugitive VOC

emissions at the plant, and this program has also been proposed for the additional fugitive VOC

emissions associated with the project. 28LAER is TCEQ’s most stringent LDAR program,

developed to satisfy LAER requirements in ozone non-attainment areas.


Due to the negligible amount of GHG emissions from process fugitives, the only available

control, implementation of an LDAR program, is clearly not cost effective, and BACT is

determined to be no control. However, Enterprise will implement TCEQ’s 28LAER LDAR

program for VOC BACT/LAER purposes, which will also effectively minimize GHG emissions.

Therefore, the proposed VOC LDAR program more than satisfies GHG BACT requirements.

6.8 Diesel Engines

The diesel engines will be used for emergency purposes only, and the only non-emergency

operation will be for testing one hour per week each, or 52 weeks/yr.


The RBLC database did not include any control technologies for GHG emissions from

emergency use engines. The technologies that were considered for the engines included:

Low carbon fuel,

Good combustion practice and maintenance, and

Limited operation.


Use of lower carbon fuel such as natural gas is not considered feasible for an emergency

engine. Natural gas supplies may be unavailable in emergency situations, and maintaining the

required fuel in an on-board tank associated with each engine is the only practical fuel option.

Good combustion practice and maintenance and limited operation are both applicable and

feasible.


Limited operation and good combustion practices and maintenance are all effective in

minimizing emissions, but do not lend themselves to ranking by effectiveness.

6-24


Limited operation is directly applicable to the proposed engines since they are for emergency

use only, resulting in no emissions at most times. Operation for testing purposes is necessary

to ensure operability when needed. Properly designed and maintained engines constitutes

good operating practice for all maximizing efficiency of all fuel combustion equipment, including

emergency engines.


Enterprises proposes to use properly designed and maintained engines to minimize emissions.

Emergency use only inherently results in low annual emissions and normal operation will be

limited to 52 hours per year for scheduled testing only. This minimal use results in an

insignificant contribution to the total project GHG emissions making consideration of additional

controls unwarranted. These practices are proposed as BACT for GHG emissions from the

engines.

CCS System Component

Cost ($/ton of CO2

Controlled)1Tons of CO2

Controlled per Year2Total Annualized

Cost

CO2 Capture and Compression Facilities $103 1,153,427 $118,803,012

CO2 Transport Facilities3 Not Included Not Included Not Included

CO2 Storage Facilities $0.51 1,153,427 $588,248

Total CCS System Cost $104 1,153,427 $119,391,260

Proposed Plant Cost Total Capital Cost

Capital Recovery

Factor4Annualized Capital

Cost

Cost of PDH Unit without CCS $1,300,000,000 0.0944 $122,710,803

4. Capital recovery factor based on 7% interest rate and 20 year equipment life.

Interest Rate 7%Equipent Life (yrs) 20

Approximate Cost for Construction and Operation of a Post-Combustion CCS System for PDH Plant

1. Costs are from Report of the Interagency Task Force on Carbon Capture (August, 2010) . A range of costs was provided for transport and storage facilities; for conservatism, the low ends of these ranges were used in this analysis as they contribute little to the total cost. Reported costs in $/tonne were converted to $/ton.

2. Tons of CO2 controlled assumes 90% capture of all CO2 emissions from the proposed combustion units.

3. Pipeline costs are not included at this time. It is conservatively assumed that a suitable sequestration site is available in close proximaity to the proposed PDH Unit.

Table 6-1

6-25

Appendix A

Emissions Calculations

Table A-1 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitGHG Emissions - Individual Combustion Unit Limts

CO2 CH4 N2O CO2e

HR15.101 HR15.101 Reactor Charge Heater DeEth Offgas 3,758,478 2,503,713,725 0.765 26.66 246,846 12.43 2.49 247,877 Ethane 287,383,412 0.798 30.07 33,322 0.56 0.06 33,351 Natural Gas 494,432,362 0.723 17.46 30,139 0.56 0.06 30,168

Reactor Charge Heater Total/Max34,267,060 280,168 12.99 2.54 281,229

DW37.101 All of Below: Waste Heat Boiler:

HR15.103 Waste Heat Boiler Burner Ethane 297,241 167,961,130 0.798 30.07 19,475 0.33 0.03 19,492 DeEth Offgas 297,241 198,007,252 0.765 26.66 19,522 0.98 0.20 19,603

Natural Gas 297,241 288,970,814 0.723 17.46 17,615 0.33 0.03 17,632 PSA Tail Gas 297,241 599,900,478 0.443 11.14 14,315 0.33 0.03 14,332

LTRU Offgas4- - 0.270 4.03 - - - -

WHB Burner Total/Max5297,241 19,522 0.98 0.20 19,603

HR15.102 Regeneration Air Heater Ethane 4,789,100 2,706,164,815 0.798 30.07 313,779 5.28 0.53 314,053 DeEth Offgas 3,758,478 2,503,713,725 0.765 26.66 246,846 12.43 2.49 247,877 PSA Tail Gas 1,870,421 3,774,941,116 0.443 11.14 90,079 6.19 1.24 90,593 Natural Gas 4,789,100 4,655,854,889 0.723 17.46 283,807 15.84 3.17 285,121

LTRU Offgas4- - 0.270 4.03 - - - -

Regeneration Air Heater Total/Max610 417 999 650 704 23 89 4 25 652 523

508,582

Carbon Content

(CC)MW

(lb/lbmol)

Emission Rates (tpy)2Firing Rate

(scf/yr)EPN FIN Description Fuel1Firing Rate(mmBtu/yr)

Regeneration Air Heater Total/Max 10,417,999 650,704 23.89 4.25 652,523

GT26.101A Regen Air Comp. Gas Turbine A Natural Gas 2,107,571 2,048,933,053 0.723 17.46 124,897 2.32 0.23 125,018

GT26.101B Regen Air Comp. Gas Turbine B Natural Gas 2,107,571 2,048,933,053 0.723 17.46 124,897 2.32 0.23 125,018

BO10.103A BO10.103A Auxiliary Boiler A Ethane 248,500 140,419,280 0.798 30.07 16,282 0.27 0.03 16,296

BO10.103B BO10.103B Auxiliary Boiler B Natural Gas 248,500 241,586,096 0.723 17.46 14,726 0.82 0.16 14,795 PSA Tail Gas 248,500 501,530,283 0.443 11.14 11,968 0.82 0.16 12,036 DeEth Offgas 248,500 165,538,513 0.765 26.66 16,321 0.82 0.16 16,389

Auxiliary Boiler Total/Max7 248,500 16,321 0.82 0.16 16,389

1 Listed fuels are the fuels that may be burned in each facility. All available DeEth Offgas and PSA Tail Gas will be used, and balance of required fuel will be natural gas and/or ethane.

The fuel firing rates used for each facility are based on burning all available DeEth Offgas and PSA Tail Gas in the preferred facility, up to the required heat demand on that facility.

Any remaining off/tail gas will be used in other facilities as shown. As such, the individual fuel usage rates used in the calculations are not maximum annual rates for each facility.

2 Note all emission rates are in units of short tons. Eq. C-5 in 40 CFR Part 98 Chapter C yields emissions in metric tons.

Metric tons were converted to short tons by multiplying by 1.102311 short tons per metric ton.

3 All available DeEth Offgas will be burned in Reactor Charge Heater with balance of fuel being either natural gas or ethane. Total maximum emission rate is emissions

from DeEth Offgas plus maximum from ethane or natural gas.

4 LTRU Offgas will only be burned if the PSA Unit is down, which is an upset condition and thus not shown in the calculations.

5 PSA Tail Gas is primary fuel for WHB Burner. Natural gas and ethane are alternate fuels. Maximum emission rate shown is based on burning 100% ethane.

6 Regeneration Air Heater will burn any DeEth Offgas and PSA Tail Gas not consumed in the Charge Heater and WHB Burner. Total/Max emissions are based on burning PSA Tail

Gas not used in WHB Burner with balance of fuel from Ethane/DeEth Offgas. (Note that CO2 emission factor in lb/mmbtu for Ethane and DeEth Offgas are the same (see table below)).7 Auxiliary Boilers will be in hot standby under normal conditions and will be used interchangeably; thus, the firing rates shown are totals for the two together. They are capable of burning each of the fuels listed, and maximum emissions are based on burning all DeEth Offgas, which results in the highest CO2 emisions.

12/18/2012

Table A-1 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitGHG Emissions - Individual Combustion Unit Limts

Carbon Factor Calculations:

Component

Molecular Weight

(lb/lb-mol)

Number of Carbons per mole Natural Gas

DeEth Offgas (SOR)

PSA Tail Gas (SOR) LTRU Offgas

Import Ethane

MSS Flaring

Reactor VOC

Nitrogen 28.013 0 0.683 0.490 6.760 1.490 0.000 0.000 0.000Carbon Dioxide 44.010 1 1.797 2.200 0.520 0.120 0.000 0.000 0.000Carbon Monoxide 28.010 1 0.035 1.630 12.470 2.750 0.000 0.000 0.000Helium 4.003 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000Argon 39.95 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000Hydrogen 2.02 0 0.000 8.860 60.070 91.190 0.000 0.000 0.000Methane 16.04 1 93.361 7.680 13.960 3.080 0.000 0.000 0.000Ethane 30.07 2 3.043 71.330 3.470 0.770 100.000 0.000 1.530Propane 44.10 3 0.557 0.060 0.760 0.170 0.000 50.000 8.113Iso-Butane 58.12 4 0.191 0.000 0.000 0.000 0.000 0.000 0.000n-Butane 58.12 4 0.143 0.000 0.000 0.000 0.000 0.000 9.672Iso-Pentane 72.15 5 0.039 0.000 0.000 0.000 0.000 0.000 0.000n-Pentane 72.15 5 0.027 0.000 0.000 0.000 0.000 0.000 7.792n-Hexane 86.18 6 0.088 0.000 0.000 0.000 0.000 0.000 14.234n-Heptane 100.20 7 0.000 0.000 0.000 0.000 0.000 0.000 12.241C10+ 140.00 10 0.000 0.000 0.000 0.000 0.000 0.000 43.807Ethylene 28.05 2 0.000 7.170 0.970 0.210 0.000 0.000 0.182P l 42 08 3 0 000 0 310 1 010 0 220 0 000 50 000 2 429

Composition (mole %)

Propylene 42.08 3 0.000 0.310 1.010 0.220 0.000 50.000 2.429neo-Pentane 72.15 5 0.000 0.000 0.000 0.000 0.000 0.000 0.000Acetylene 26.04 2 0.000 0.220 0.010 0.000 0.000 0.000 0.000Hydrogen Sulfide 34.00 0 0.000 0.050 0.000 0.000 0.000 0.000 0.000Oxygen 32.00 0 0.037 0.000 0.000 0.000 0.000 0.000 0.000Water 18.02 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000

MW (lb/lbmole): 17.46 26.66 11.14 4.03 30.07 43.09 102.22Carbon Content (kg C/kg Fuel): 0.723 0.765 0.443 0.270 0.798 0.835 0.847

Heating Value (btu/scf, HHV): 1028.6 1501.2 495.5 362.0 1769.7 NA NACO2 emission factor (lb/mmbtu,HHV): 118.55 131.39 96.35 29.10 131.04

Emission Factors:

Eq. C-5 from 40 CFR Part 98 Chapter CCO2e Equivalents:

kg CH4 /mmBtu kg N2O/mmBtu CO2 1.0Natural Gas 0.001 0.0001 CH4 21.0

CO2 = CO2 emissions, metric tons/yr Process Gas 0.003 0.0006 N2O 310.0Fuel = firing rate in mmscf/yr kg to lb conversion factor: 2.20462MVC = 836.6 (per Part 98)CC = as calculated aboveMW = as calculated above

CH4 and N2O Emission factors from Table C-2 of Appendix A to 40 CFR Part 98 Chapter C

12/18/2012

Table A-2 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitGHG Emissions - Combustion Unit Caps

HR15.101 HR15.101 Reactor Charge Heater 4,267,060

DW37.101 All of Below: Waste Heat Boiler:

HR15.103 Waste Heat Boiler Burner 297,241

HR15.102 Regeneration Air Heater 10,417,999

GT26.101A Regen Air Comp. Gas Turbine A 2,107,571

GT26.101B Regen Air Comp. Gas Turbine B 2,107,571

BO10.103A BO10.103A Auxiliary Boiler A

BO10.103B BO10.103B Auxiliary Boiler B

Total from Above Combustion Units 19,445,942

Available Fuels:

DeEth Offgas 3,758,478

PSA Tail Gas 2,167,662

Ethane 9,304,660

Natural Gas 4,215,142

Fuel Total 19,445,942

GHG Emission Calculation

CO2 CH4 N2O CO2e

EPN FIN DescriptionFiring Rate(mmBtu/yr)

Fuel1Firing Rate(mmBtu/yr)

248,500

Emission Rates (tpy)2

1. DeEth Offgas and PSA Tail Gas firing rates are all of these fuels that are projected to be produced annual in the process. All of these fuel gases will be burned in the PDH Unit combustion devices and the balance of the fuel requirements will be made up with either ethane or natural gas. Natural gas is the only fuel that will be fired in the Gas Turbines, and the natural gas firing rate shown is the fuel required for the two Gas Turbines. For the maximum annual GHG emissions calculations all remaining fuel requirements are assumed to be provided by ethane as ethane results in higher GHG emissions per btu than natural gas.

Firing Rate (scf/yr)

Carbon Content (CC)

MW (lb/lbmol)Fuel

Firing Rate(mmBtu/yr)

DeEth Offgas 3,758,478 2,503,713,725 0.765 26.66 246,846 12.43 2.49 247,877

PSA Tail Gas 2,167,662 4,374,841,594 0.443 11.14 104,394 7.17 1.43 104,989

Ethane 9,304,660 5,257,761,370 0.798 30.07 609,635 30.77 6.15 612,189

Natural Gas 4,215,142 4,097,866,106 0.723 17.46 249,794 13.94 2.79 250,950

Fuel Total 19,445,942 NA NA NA 1,210,669 64.31 12.86 1,216,006

VOC from Reactors NA 13,333,260 0.847 102.22 5,580 - - 5,580

Coke Burn3 NA NA NA NA 60,000 - - 60,000

Cap Total NA NA NA NA 1,276,248 64.31 12.86 1,281,586

3. CO2 from coke burn based on Lummus EOR estimate of 58,000 tpy, rounded to 60,000 tpy.

2. Note all emission rates are in units of short tons. Eq. C-5 in 40 CFR Part 98 Chapter C yields emissions in metric tons. Metric tons were converted to short tons by multiplying by 1.102311 short tons per metric ton.

12/18/2012

Table A-2 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitGHG Emissions - Combustion Unit Caps


Component

Molecular Weight

(lb/lb-mol)

Number of Carbons per

mole Natural Gas

DeEth Offgas (SOR)

PSA Tail Gas (SOR)

Import Ethane

Reactor VOC

LTRU

Offgas4

Nitrogen 28.013 0 0.683 0.490 6.760 0.000 0.000 1.490Carbon Dioxide 44.010 1 1.797 2.200 0.520 0.000 0.000 0.120Carbon Monoxide 28.010 1 0.035 1.630 12.470 0.000 0.000 2.750Helium 4.003 0 0.000 0.000 0.000 0.000 0.000 0.000Argon 39.95 0 0.000 0.000 0.000 0.000 0.000 0.000Hydrogen 2.02 0 0.000 8.860 60.070 0.000 0.000 91.190Methane 16.04 1 93.361 7.680 13.960 0.000 0.000 3.080Ethane 30.07 2 3.043 71.330 3.470 100.000 1.530 0.770Propane 44.10 3 0.557 0.060 0.760 0.000 8.113 0.170Iso-Butane 58.12 4 0.191 0.000 0.000 0.000 0.000 0.000n-Butane 58.12 4 0.143 0.000 0.000 0.000 9.672 0.000Iso-Pentane 72.15 5 0.039 0.000 0.000 0.000 0.000 0.000n-Pentane 72.15 5 0.027 0.000 0.000 0.000 7.792 0.000n-Hexane 86.18 6 0.088 0.000 0.000 0.000 14.234 0.000n-Heptane 100.20 7 0.000 0.000 0.000 0.000 12.241 0.000C10+ 140.00 10 0.000 0.000 0.000 0.000 43.807 0.000Ethylene 28.05 2 0.000 7.170 0.970 0.000 0.182 0.210Propylene 42.08 3 0.000 0.310 1.010 0.000 2.429 0.220neo-Pentane 72.15 5 0.000 0.000 0.000 0.000 0.000 0.000Acetylene 26.04 2 0.000 0.220 0.010 0.000 0.000 0.000Hydrogen Sulfide 34.00 0 0.000 0.050 0.000 0.000 0.000 0.000Oxygen 32.00 0 0.037 0.000 0.000 0.000 0.000 0.000Water 18.02 0 0.000 0.000 0.000 0.000 0.000 0.000

MW (lb/lbmole): 17.46 26.66 11.14 30.07 102.22 4.03Carbon Content (kg C/kg Fuel): 0.723 0.765 0.443 0.798 0.847 0.270

Heating Value (btu/scf, HHV): 1028.6 1501.2 495.5 1769.7 NA 362.0


Heating Value (btu/scf, HHV): 1028.6 1501.2 495.5 1769.7 NA 362.0CO2 emission factor (lb/mmbtu,HHV): 118.55 131.39 96.35 131.04 NA 29.10

4 LTRU Offgas will only be burned if the PSA Unit is down, which is an upset condition and thus not shown in the calculations.

Emission Factors:

Eq. C-5 from 40 CFR Part 98 Chapter Ckg CH4 /mmBtu kg N2O/mmBtu

Natural Gas 0.001 0.0001Process Gas 0.003 0.0006

CO2 = CO2 emissions, metric tons/yr kg to lb conversion factor: 2.20462Fuel = firing rate in mmscf/yrMVC = 836.6 (per Part 98) CO2e Equivalents:CC = as calculated above CO2 1.0MW = as calculated above CH4 21.0

N2O 310.0


12/18/2012

Table A-3 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitProcess Flare

CO2 CH4 N2O CO2e SK25.801 SK25.801 Process Flare, Routine

Pilots Natural Gas 9,011 8,760,000 0.723 17.46 534 0.0099 0.0010 534 Purge Natural Gas 16,399 15,943,200 0.723 17.46 972 0.0181 0.0018 973 Routine Steams Vent Gas 3,354 7,545,545 0.835 43.09 1,312 0.0111 0.0022 1,313 Routine Total 2,818 0.04 0.005 2,821

Process Flare, MSS Misc. MSS Vent Gas 2,061 8,613,636 0.835 43.09 1,498 0.0068 0.0014 1,499 Startup MSS Vent Gas 46,006 45,913,143 0.735 17.96 2,928 0.1521 0.0304 2,941 Shutdown MSS Vent Gas 6,944 8,613,636 0.832 43.29 1,498 0.0230 0.0046 1,500 MSS Total 4,426 0.16 0.03 4,439

1 Note all emission rates are in units of short tons. Eq. C-5 in 40 CFR Part 98 Chapter C yields emissions in metric tons.

Metric tons were converted to short tons by multiplying by 1.102311 short tons per metric ton.


Component

Molecular Weight

(lb/lb-mol)

Number of Carbons per mole Natural Gas

Startup Flaring MSS Flaring

Shutdown Flaring

Nitrogen 28.013 0 0.683 0.000 0.000 0.000Carbon Dioxide 44.010 1 1.797 2.000 0.000 0.000Carbon Monoxide 28.010 1 0.035 0.000 0.000 0.000Helium 4.003 0 0.000 0.000 0.000 0.000Argon 39.95 0 0.000 0.000 0.000 0.000Hydrogen 2.02 0 0.000 0.000 0.000 0.000Methane 16.04 1 93.361 93.000 0.000 0.000Ethane 30.07 2 3.043 0.000 0.000 0.000Propane 44.10 3 0.557 3.000 50.000 60.000Iso-Butane 58.12 4 0.191 0.000 0.000 0.000n-Butane 58.12 4 0.143 0.000 0.000 0.000Iso-Pentane 72.15 5 0.039 0.000 0.000 0.000n-Pentane 72.15 5 0.027 0.000 0.000 0.000n-Hexane 86.18 6 0.088 0.000 0.000 0.000n-Heptane 100.20 7 0.000 0.000 0.000 0.000C10+ 140.00 10 0.000 0.000 0.000 0.000Ethylene 28.05 2 0.000 0.000 0.000 0.000P l 42 08 3 0 000 2 000 50 000 40 000



EPN FIN Description FuelFiring Rate(mmBtu/yr)

Firing Rate (scf/yr)

Carbon Content

(CC)MW

(lb/lbmol)

Propylene 42.08 3 0.000 2.000 50.000 40.000neo-Pentane 72.15 5 0.000 0.000 0.000 0.000Acetylene 26.04 2 0.000 0.000 0.000 0.000Hydrogen Sulfide 34.00 0 0.000 0.000 0.000 0.000Oxygen 32.00 0 0.037 0.000 0.000 0.000Water 18.02 0 0.000 0.000 0.000 0.000

MW (lb/lbmole): 17.46 17.96 43.09 43.29Carbon Content (kg C/kg Fuel): 0.723 0.735 0.835 0.832

Heating Value (btu/scf, HHV): 1028.6 1028.6 311.0 927.6CO2 emission factor (lb/mmbtu,HHV): 118.55

Emission Factors:

Eq. C-5 from 40 CFR Part 98 Chapter CCO2e Equivalents:

kg CH4 /mmBtu kg N2O/mmBtu CO2 1.0Natural Gas 0.001 0.0001 CH4 21.0

CO2 = CO2 emissions, metric tons/yr Process Gas 0.003 0.0006 N2O 310.0Fuel = firing rate in mmscf/yr kg to lb conversion factor: 2.20462MVC = 836.6 (per Part 98)CC = as calculated aboveMW = as calculated above


12/18/2012

Table A-4 Pipeline Fugitive GHG EmissionEnterprise Operating Products LLCMont Belvieu Complex - PDH Unit

EPN LDAR EPN LDARFUG-NGAS AVO FUG-PDH 28LAER

Annual AnnualComponent Stream Control Emissions Control Emissions

Type Type Eff. (tpy) Eff. (tpy)

Gas/Vapor 0.0089 140 30% 3.8202 1,119 97% 1.3086

Light Liquid 0.0035 0 0% 0.0000 1495 97% 0.6876

Heavy Liquid 0.0007 0 0% 0.0000 0 97% 0.0000

Light Liquid 0.0386 0 0% 0.0000 51 93% 0.6036

Heavy Liquid 0.0161 0 0% 0.0000 0 93% 0.0000

Gas/Vapor 0.0029 350 30% 3.1120 3,851 97% 1.4675

Light Liquid 0.0005 0 0% 0.0000 5263 97% 0.3458

Heavy Liquid 0.00007 0 0% 0.0000 0 97% 0.0000

Compressors Gas/Vapor 0.5027 0 0% 0.0000 4 95% 0.4404

Relief Valves Gas/Vapor 0.2293 10 30% 7.0303 45 100% 0.0000

Open Ends 0.004 0 0% 0.0000 0 97% 0.0000

Sample Con. 0.033 0 0% 0.0000 32 97% 0.1388

Gas/Vapor 0 0 0% 0.0000 0 97% 0.0000

Lt/Hvy Liquid 0 0 0% 0.0000 0 97% 0.0000Process Drains 0.07 0 0% 0.0000 0 97% 0.0000

TOTAL 500 Total Loss 13.96 11,860 Total Loss 4.99

Operating Hours: 8,760 % CH4 93% % CH4 5%Total CH4 13.04 Total CH4 0.25

GWP 21 GWP 21CO2e 273.75 CO2e 5.24

Flanges

Other

Number of Components

Number of Components

Emission Factor SOCMI without

Ethylene

Valves

Pumps

12/18/2012

Table A-5 GHG Emission CalculationsEnterprise Operating Products LLCMont Belvieu Complex - PDH UnitDiesel Engines

CO2 CH4 N2O CO2e PM18.803 PM18.803 Fire Water Pump Engine No. 2 Diesel 3.79 52 197 16.1 0.0007 0.0001 16.1

PM18.850C PM18.850C Raw Water Pump Engine No. 2 Diesel 1.97 52 103 8.4 0.0003 0.0001 8.4

Emission Factors:

CO2e Equivalents:Fuel kg CO2/mmBtu kg CH4 /mmBtu kg N2O/mmBtu CO2 1.0

No. 2 Distillate 73.96 0.003 0.0006 CH4 21.0N2O 310.0

kg to lb conversion factor: 2.20462

Firing Rate (mmbtu/hr)

Usage (hrs/yr)


Emission factors from Tables C-1 & C-2 of Appendix A to 40 CFR Part 98 Chapter C

EPN FIN Description FuelFiring Rate(mmbtu/yr)

12/18/2012

Appendix B

RBLC Database Search Results

Appendix BRBLC Database Search Results for GHG Emissions from Boilers

RBLCID FACILITY_NAME COMPANY_NAME STATEPERMIT DATE PROCESS_NAME

PRIMARY FUEL THROUGHPUT POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1

AL‐0231 NUCOR DECATUR LLC NUCOR CORPORATION AL 06/12/2007 &

VACUUM DEGASSER

BOILER NATURAL GAS 95 MMBTU/H Carbon Dioxide 0.061 LB/MMBTU

*FL‐0330

PORT DOLPHIN ENERGY

LLC

PORT DOLPHIN ENERGY

LLC FL 12/01/2011 &Boilers (4 ) natural gas 278 MMBTU/H Carbon Dioxide

tuning, optimization,

instrumentation and controls,

insulation, and turbulent flow. 117 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Primary Reformer natural gas 1.13

million cubic

feet/hr Carbon Dioxide good combustion practices 117 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER


million cubic

feet/hr Methane good combustion practices 0.0023 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER


million cubic

feet/hr Methane good combustion practices 0.0023 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER


million cubic

feet/hr

Carbon Dioxide

Equivalent (CO2e) good combustion practices 596905 TONS/YR

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Auxiliary Boiler natural gas 472.4 MMBTU/hr Carbon Dioxide good combustion practices 117 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Auxiliary Boiler natural gas 472.4 MMBTU/hr Methane good combustion practices 0.0023 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Auxiliary Boiler natural gas 472.4 MMBTU/hr Nitrous Oxide (N2O) good combustion practices 0.0006 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Auxiliary Boiler natural gas 472.4 MMBTU/hr

Carbon Dioxide


IN‐0135

HOOSIER ENERGY REC

INC. ‐ MEROM

GENERATING STATION

HOOSIER ENERGY REC

INC. ‐ MEROM

GENERATING STATION IN 11/10/2011 &

COAL BED METHANE

CBM DEHYDRATOR

UNITS (CBM‐FIRED

REBOILER AND FLASH

TANK)

COAL BED

METHANE 0.5 MMBTU/H Carbon Dioxide PROPER MAINTENANCE 59.36 LB/H

LA‐0248

DIRECT REDUCTION

IRON PLANT

CONSOLIDATED

ENVIRONMENTAL

MANAGEMENT INC ‐

NUCOR LA 01/27/2011 &

DRI‐108 ‐ DRI Unit #1

Reformer Main Flue

Stack

Iron Ore and

Natural Gas 12168 Billion Btu/yr Carbon Dioxide

good combustion practices, the

Acid gas separation system, and

Energy integration. 11.79

MMBTU/TON OF

DRI

LA‐0248

DIRECT REDUCTION

IRON PLANT

CONSOLIDATED

ENVIRONMENTAL

MANAGEMENT INC ‐

NUCOR LA 01/27/2011 &

DRI‐208 ‐ DRI Unit #2

Reformer Main Flue

Stack

Iron ore and

Natural Gas 12168 Billion Btu/yr Carbon Dioxide

good combustion practices, the

Acid gas separation system, and

Energy integration. 11.79

MMBTU/TON OF

DRI

LA‐0254

NINEMILE POINT

ELECTRIC GENERATING

PLANT ENTERGY LOUISIANA LLC LA 08/16/2011 &AUXILIARY BOILER (AUX‐NATURAL GAS 338 MMBTU/H Methane

PROPER OPERATION AND GOOD

COMBUSTION PRACTICES 0.0022 LB/MMBTU

LA‐0254

NINEMILE POINT

ELECTRIC GENERATING

PLANT ENTERGY LOUISIANA LLC LA 08/16/2011 &

AUXILIARY BOILER

(AUX‐1) NATURAL GAS 338 MMBTU/H Nitrous Oxide (N2O)


COMBUSTION PRACTICES 0.0002 LB/MMBTU

LA‐0254

NINEMILE POINT

ELECTRIC GENERATING

PLANT ENTERGY LOUISIANA LLC LA 08/16/2011 &

AUXILIARY BOILER

(AUX‐1) NATURAL GAS 338 MMBTU/H Carbon Dioxide


COMBUSTION PRACTICES 117 LB/MMBTU

*NE‐0054

CARGILL,

INCORPORATED CARGILL, INCORPORATED NE 03/01/2013 &Boiler K natural gas 300 mmbtu/h

Carbon Dioxide

Equivalent (CO2e) good combustion practices 0

RBLC Search of GHG BACT Database

12‐Nov

RBLC Database Search Results for GHG Emissions from Heaters



*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Startup Heater Natural gas 110.12 MMBTU/hr Carbon Dioxide good combustion practices 117 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Startup Heater Natural gas 110.12 MMBTU/hr Methane good combustion practices 0.0023 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Startup Heater Natural gas 110.12 MMBTU/hr Nitrous Oxide (N2O) good combustion practices 0.0006 LB/MMBTU

*IA‐0105

IOWA FERTILIZER

COMPANY

IOWA FERTILIZER

COMPANY IA 10/26/2012 &Startup Heater Natural gas 110.12 MMBTU/hr

Carbon Dioxide


*MN‐0085

ESSAR STEEL

MINNESOTA LLC

ESSAR STEEL MINNESOTA

LLC MN 05/10/2012 &INDURATING FURNACE NATURAL GAS 542 MMBTU/H Carbon Dioxide 710000 TON/YR

RBLC Database Search Results for GHG Emissions from Simple Cycle Turbines



LA‐0257

SABINE PASS LNG

TERMINAL

SABINE PASS LNG, LP &

SABINE PASS

LIQUEFACTION, LL LA 12/06/2011 &

Simple Cycle

Refrigeration

Compressor Turbines

(16) Natural Gas 286 MMBTU/H

Carbon Dioxide

Equivalent (CO2e)

Good combustion/operating

practices and fueled by natural gas ‐

use GE LM2500+G4 turbines 4872107 TONS/YR

LA‐0257

SABINE PASS LNG

TERMINAL

SABINE PASS LNG, LP &

SABINE PASS

LIQUEFACTION, LL LA 12/06/2011 &

Simple Cycle

Generation Turbines

(2) Natural Gas 286 MMBTU/H

Carbon Dioxide

Equivalent (CO2e)

Good combustion/operating

practices and fueled by natural gas ‐

use GE LM2500+G4 turbines 4872107 TONS/YR

RBLC Database Search Results for GHG Emissions from Flares



IN‐0135

HOOSIER ENERGY REC

INC. ‐ MEROM

GENERATING STATION

HOOSIER ENERGY REC

INC. ‐ MEROM


COAL BED METHANE‐

FIRED STANDBY FLARE

W/PROPANE‐FIRED

PILOT

COAL BED

METHANE 25 MMBTU/H Carbon Dioxide

GOOD COMBUSTION PRACTICES

AND PROPER MAINTENANCE 3235 LB/MW‐H

IN‐0135

HOOSIER ENERGY REC

INC. ‐ MEROM

GENERATING STATION

HOOSIER ENERGY REC

INC. ‐ MEROM


COAL BED METHANE‐

FIRED STANDBY FLARE

W/PROPANE‐FIRED

PILOT

COAL BED

METHANE 25 MMBTU/H Methane


AND PROPER MAINTENANCE 0.06 LB/MW‐H

IN‐0135

HOOSIER ENERGY REC

INC. ‐ MEROM

GENERATING STATION

HOOSIER ENERGY REC

INC. ‐ MEROM


COAL BED METHANE‐

FIRED STANDBY FLARE

W/PROPANE‐FIRED

PILOT

COAL BED

METHANE 25 MMBTU/H Nitrous Oxide (N2O)


AND PROPER MAINTENANCE 0.05 LB/MW‐H

RBLC Search of GHG BACT Database

12‐Nov

Documents

PSD Greenhouse Gas Draft Permit for Enterprise Products ... · PDF file6.2 Regeneration Air Heater ..... 6-9 6.2.1 Step 1 – Identification of Potential Control Technologies ... fired